U.S. patent number 10,844,705 [Application Number 15/528,951] was granted by the patent office on 2020-11-24 for surface excited downhole ranging using relative positioning.
This patent grant is currently assigned to Halliburton Energy Services, Inc.. The grantee listed for this patent is Halliburton Energy Services, Inc.. Invention is credited to Burkay Donderici, Clinton James Moss.
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United States Patent |
10,844,705 |
Donderici , et al. |
November 24, 2020 |
Surface excited downhole ranging using relative positioning
Abstract
A downhole relative positioning system utilizes electromagnetic
and survey measurements from a first well to calibrate a formation
model, which is then used to improve the interpretation of
measurements from a second well. Since the methods described herein
utilize a differential approach, even though the exact position of
each wellbore may not be accurately identified, their relative
positions can be accurately identified.
Inventors: |
Donderici; Burkay (Houston,
TX), Moss; Clinton James (Humble, TX) |
Applicant: |
Name |
City |
State |
Country |
Type |
Halliburton Energy Services, Inc. |
Houston |
TX |
US |
|
|
Assignee: |
Halliburton Energy Services,
Inc. (Houston, TX)
|
Family
ID: |
1000005201630 |
Appl.
No.: |
15/528,951 |
Filed: |
January 20, 2016 |
PCT
Filed: |
January 20, 2016 |
PCT No.: |
PCT/US2016/014022 |
371(c)(1),(2),(4) Date: |
May 23, 2017 |
PCT
Pub. No.: |
WO2017/127060 |
PCT
Pub. Date: |
July 27, 2017 |
Prior Publication Data
|
|
|
|
Document
Identifier |
Publication Date |
|
US 20180313203 A1 |
Nov 1, 2018 |
|
Current U.S.
Class: |
1/1 |
Current CPC
Class: |
G01V
3/30 (20130101); E21B 7/04 (20130101); G01V
3/18 (20130101); E21B 47/0232 (20200501) |
Current International
Class: |
E21B
47/022 (20120101); E21B 7/04 (20060101); G01V
3/30 (20060101); G01V 3/18 (20060101); E21B
47/0232 (20120101) |
References Cited
[Referenced By]
U.S. Patent Documents
Foreign Patent Documents
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|
|
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WO 2014/098891 |
|
Jun 2014 |
|
WO |
|
WO 2015/099785 |
|
Jul 2015 |
|
WO |
|
Other References
Merriam-webster definition of second, 1 page, May 16, 2019. cited
by examiner .
Merriam-webster definition of range, 1 page, May 16, 2019. cited by
examiner .
Pioneer Natural Resources Uses Active Magnetic Ranging to Avoid
Risk of Wellbore Collision, Halliburton, 2 pages (Year: 2008).
cited by examiner .
International Search Report and the Written Opinion of the
International Search Authority, or the Declaration, dated Sep. 12,
2016, PCT/US2016/014022, 9 pages, ISA/KR. cited by
applicant.
|
Primary Examiner: Lau; Tung S
Attorney, Agent or Firm: Haynes and Boone, LLP
Claims
What is claimed is:
1. A method for downhole ranging, comprising: obtaining first
measurement signals in a first wellbore; obtaining second
measurement signals in a second wellbore; calculating a relative
measurement between the first and second measurement signals;
determining a position of the second wellbore relative to the first
wellbore using the relative measurement; and using the relative
measurement to perform downhole ranging.
2. A method as defined in claim 1, wherein calculating the relative
measurement comprises calculating a differential measurement
between the first and the second measurement signals.
3. A method as defined in claim 2, wherein calculating the relative
measurement further comprises calculating a ratio of the
differential measurement to the first or second measurement
signals.
4. A method as defined in claim 1, wherein calculating the relative
measurement further comprises calculating a ratio of: the first
measurement signal to the second measurement signal; or the second
measurement signal to the first measurement signal.
5. A method as defined in claim 1, wherein determining the position
of the second wellbore comprises performing an inversion using
survey data from the first or second wellbores.
6. A method as defined in claim 2, wherein determining the position
of the second wellbore comprises performing an inversion using:
survey data from the first or second wellbores; and a ratio of the
differential measurement to the first or second measurement
signals.
7. A method as defined in claim 5, wherein performing the inversion
comprises performing the inversion using a ratio of: the first
measurement signal to the second measurement signal; or the second
measurement signal to the first measurement signal.
8. A method as defined in claim 1, wherein: obtaining the first
measurement signal comprises: deploying a first sensor along the
first wellbore; emitting a first source signal toward the first
wellbore; and measuring the first source signal using the first
sensor, thereby acquiring the first measurement signal; and
obtaining the second measurement signal comprises: deploying a
second sensor along the second wellbore; emitting a second source
signal toward the second wellbore; and measuring the second source
signal using the second sensor, thereby acquiring the second
measurement signal.
9. A method as defined in claim 1, wherein obtaining the first and
second measurement signals comprises emitting a source signal
toward the first and second wellbores using a surface excitation
source.
10. A method as defined in claim 1, wherein obtaining the first and
second measurement signals comprises acquiring bi-axial or triaxial
measurement signals.
11. A method as defined in claim 1, wherein: the first measurement
signal is obtained using a first sensor; and the second measurement
signal is obtained using the first sensor at a different time.
12. A method as defined in claim 1, wherein: the first measurement
signal is obtained using a first sensor; and the second measurement
is obtained using a second sensor.
13. A method as defined in claim 12, wherein the first and second
sensors are calibrated using a same excitation source.
14. A method as defined in claim 1, wherein obtaining the first and
second measurement signals comprise at least one of acquiring
absolute, phase, or real or imaginary measurements.
15. A method as defined in claim 1, wherein the first and second
measurement signals are obtained using a sensor deployed on a
bottom hole assembly.
16. A method as defined in claim 15, further comprising steering
the bottom hole assembly deployed along the second wellbore using
the determined position of the second wellbore.
17. A method as defined in claim 1, further comprises avoiding the
first wellbore using the determined position of the second
wellbore.
Description
PRIORITY
The present application is a U.S. National Stage patent application
of International Patent Application No. PCT/US2016/014022, filed on
Jan. 20, 2016, the benefit of which is claimed and the disclosure
of which is incorporated herein by reference in its entirety.
FIELD OF THE DISCLOSURE
The present disclosure relates generally to downhole ranging and,
more specifically, to a relative positioning system using surface
excitation to determine and track the relative location of multiple
wellbores.
BACKGROUND
As the easy-to-access and easy-to-produce hydrocarbon resources
have been depleted over the last century, more and more difficult
wells remain. As the world's hydrocarbon demand is continuously
growing, meeting this demand requires development of more advanced
recovery procedures, one of which is the Steam Assisted Gravity
Drainage ("SAGD") application. SAGD addresses the mobility problem
of heavy oil wells by injecting high pressure and temperature steam
to reduce viscosity of the oil, thereby allowing easier extraction.
The injection is performed from a wellbore (i.e., injector) that is
drilled in parallel to the producing well (i.e., producer) at a
distance in the order of a few meters from each other. The
placement of the injector well needs to be achieved within a very
small margin of error in distance, since drilling the wells tool
closely exposes the producing well to very high
pressures/temperatures, and drilling the wells too far apart
reduces efficiency of the process.
It is well known that traditional surveying techniques based on
gravity and the earth's magnetic fields suffer from a widening cone
of uncertainty as the well gets farther from the wellhead. As a
result, such techniques cannot achieve the precision in placement
that is required in ranging applications. Therefore, most of the
existing ranging methods depend on sources that are placed in the
target well, which are not desirable due to increased cost of
maintaining an operations crew for the second well. On the other
hand, existing commercial services based on surface excitation do
not suffer from this cost problem; however, they can only perform
ranging at very shallow depths. As a result, their precision is not
good enough to place the wells reliably within the target zone in a
SAGD application.
BRIEF DESCRIPTION OF THE DRAWINGS
FIG. 1 illustrates a relative positioning system, according to an
illustrative embodiment of the present disclosure;
FIGS. 2A-2B shows an illustration of a triaxial magnetic dipole
sensor configuration at each well, in relation to a linear surface
source, according to certain illustrative embodiments of the
present disclosure;
FIG. 3 is a flow chart for a relative positioning method useful for
downhole ranging applications, according to certain illustrative
methods of the present disclosure;
FIG. 4 is a graph of the ranges of absolute and relative
measurements as a function of distance from the source to
target;
FIG. 5 is a graph showing an actual well path vs. survey
measurements with a 5% error;
FIG. 6 is a graph showing magnetic fields measured in a producer
and injector well; and
FIG. 7 is a graph showing relative ranging results versus survey
results (a 5% error is applied to survey), according to certain
illustrative embodiments of the present disclosure.
DESCRIPTION OF ILLUSTRATIVE EMBODIMENTS
Illustrative embodiments and related methodologies of the present
disclosure are described below as they might be employed in ranging
systems and methods utilizing surface excitation and the relative
positioning of a first and second wellbore. In the interest of
clarity, not all features of an actual implementation or
methodology are described in this specification. It will of course
be appreciated that in the development of any such actual
embodiment, numerous implementation-specific decisions must be made
to achieve the developers' specific goals, such as compliance with
system-related and business-related constraints, which will vary
from one implementation to another. Moreover, it will be
appreciated that such a development effort might be complex and
time-consuming, but would nevertheless be a routine undertaking for
those of ordinary skill in the art having the benefit of this
disclosure. Further aspects and advantages of the various
embodiments and related methodologies of the disclosure will become
apparent from consideration of the following description and
drawings.
As described herein, illustrative embodiments and methods of the
present disclosure describe ranging systems that improve on the
surface excitation techniques to make it more accurate and
reliable. This is achieved by utilizing electromagnetic and survey
measurements from a first well to calibrate a formation model,
which is then used to improve the interpretation of measurements
from a second well. Since the methods described herein utilize a
relative approach, even though the exact position of each wellbore
may not be accurately identified, their relative positions can be
accurately identified. Moreover, one of the many advantages to this
disclosure is that it allows the use of absolute signals rather
than gradients, which improves the operational range of the surface
system.
Although the present disclosure may be utilized in a variety of
applications, the following description will focus on applications
for accurately, and reliably positioning a well being drilled
(e.g., injector or monitoring well) with respect to a nearby target
first well, usually the producer well, so that the injector well
can be maintained approximately parallel to the producer well. The
target well must be of a higher conductivity than the surrounding
formation, which may be realized through the use of an elongated
conductive body along the target well, such as, for example, casing
which is already present in most wells to preserve the integrity of
the well and act as a conduit for flow of produced fluids. Also,
the method and system of the disclosure are particularly desirable
for the drilling of SAGD wells because the two wells can be drilled
close to one another as is required in SAGD operations. These and
other applications and/or adaptations will be understood by those
ordinarily skilled in the art having the benefit of this
disclosure.
FIG. 1 illustrates a relative positioning system 100 according to
an illustrative embodiment of the present disclosure. In this
embodiment, a producer well 10 is drilled using any suitable
drilling technique. Thereafter, producer well 10 is cased with
casing 11. An excitation source S for generating electromagnetic
("EM") waves is positioned on surface 2, along with a return R. An
injector well 12 is then drilled using bottom hole assembly ("BHA")
14 which may be, for example, a logging-while drilling ("LWD")
assembly, measurement-while drilling assembly ("MWD") or other
desired drilling assembly. Although injector well 12 is described
as being subsequently drilled, in other embodiments producer well
10 and injector well 12 may be drilled in turns. For example,
vertical and build sections of the producer well may be drilled
first, vertical and build sections of the injector well may be
drilled next, the horizontal section of the producer well may be
drilled next and the horizontal section of the injector well then
be drilled. Moreover, in yet another alternate embodiment, BHA 14
may be embodied as a wireline application (without a drilling
assembly) performing logging operations, as will be understood by
those same ordinarily skilled persons mentioned herein.
In this illustrative embodiment, the BHA/drilling assembly 14
includes one or more electromagnetic sensors 18 that sense absolute
and/or gradient electromagnetic fields emitted by surface
excitation source S. Using processing circuitry aboard BHA 14 (or
remotely located), the distance and direction from surface source S
to sensors 18 is determined by analyzing the measured absolute
electromagnetic fields at producer and injector wells 10,12, and
their relative differences. In certain illustrative embodiments,
the role of source S and sensors 18 can be changed without any
difference in system operation based on EM reciprocity theorem. For
example, surface excitation source S can be replaced by a sensor
with the same dimensions and associated antenna, and sensors 18 can
be replaced by a source with the same dimensions and associated
antenna, thereby reversing the roles. However, for simplicity only,
the system based on surface source S and downhole receivers 18 will
be presented.
Still referring to FIG. 1, excitation source S is located at or
near surface 2. In various embodiments, source S may be any type
that produces electric, magnetic or electromagnetic signals. Some
examples include electrode pair, electric dipole (e.g., wire
antenna, toroidal winding), magnetic dipole (e.g., coil, solenoid
antenna), large loop, long curved or linear wire. Excitation source
S can be voltage controlled, current controlled or a combination of
both. Source S typically produces low frequency waves with
frequencies in the order of, for example, 0.02-250 Hz, to achieve
the depth of penetration required by SAGD applications.
In other embodiments, for electronic simplicity, source S may be an
EM pulse system which provides the advantage of multi-frequency
data. Although the role of source transmitter S and sensors 18 can
be switched, it should be noted that it is more advantageous to
have source S at the surface due to easier access to higher levels
of power required for source operation. In order to achieve 3D
positioning, multiple sources S are required, each of which are
located at a different position at surface 2. Each source S can be
activated sequentially or simultaneously. In the latter case, each
source S can be differentiated by its frequency of operation. Due
to relative measurements between the wellbores described herein,
source S is required to be stable with respect to the signal level
that it generates, which indicates minimal variation with time. To
achieve this, the power source system may require stabilization via
an internal calibration feedback loop and thermal insulation or
control.
In this embodiment, sensors/receivers 18 are located along BHA 14
and measure all three components of the electric or magnetic
fields, which could be x, y and z in the tool coordinates (i.e.,
triaxial). Even though use of absolute signals is sufficient for
the illustrative embodiments herein, more information can be
obtained by measuring phase, real or imaginary components, or
gradiometric information in alternate embodiments. Here,
gradiometric information may be associated with the measurements in
complex domain, phase or amplitude. Due to specific operational
bands of excitation source S, sensors 18 must be sensitive at this
range. Thus, in certain illustrative embodiments, sensors 18 may
be, for example, an electrode pair, electric dipole (wire antenna,
toroidal winding), magnetic dipole (coil, solenoid antenna),
electric loop or magnetometer. The magnetometers/sensors can be of
flux-gate or atomic type.
Furthermore, although not shown, BHA 14 includes processing
circuitry necessary (i.e., system control center) to achieve the
relative positioning of the present disclosure in real-time. Such
circuitry includes a communications unit to facilitate interaction
between the drilling system and a remote location (such as the
surface). A visualization unit may also be connected to
communications unit to monitor the measurement data being process;
for example, an operator may intervene the system operations based
on this data. A data processing unit may convert the received data
into information giving the target's position, direction and
orientation in real-time. Thereafter, results may be displayed via
the visualizing unit.
The system control center of BHA 14 also includes the
storage/communication circuitry necessary to perform the
calculations described herein. In certain embodiments, that
circuitry is communicably coupled to sensors 18 in order to process
the received EM fields 20,22. Additionally, the circuitry on-board
BHA 14 may be communicably coupled via wired or wireless
connections to the surface to thereby communicate data back uphole
and/or to other assembly components (to steer a drill bit forming
part of assembly 14, for example). In an alternate embodiment, the
system control center or other circuitry necessary to perform one
or more aspects of the techniques described herein may be located
at a remote location away from BHA 14, such as the surface or in a
different wellbore. In other embodiments, the electromagnetic field
measurements may be communicated remotely to the system control
center for processing. These and other variations will be readily
apparent to those ordinarily skilled in the art having the benefit
of this disclosure.
Moreover, the on-board circuitry includes at least one processor
and a non-transitory and computer-readable storage, all
interconnected via a system bus. Software instructions executable
by the system control center for implementing the illustrative
relative positioning methodologies described herein in may be
stored in local storage or some other computer-readable medium. It
will also be recognized that the positioning software instructions
may also be loaded into the storage from a CD-ROM or other
appropriate storage media via wired or wireless methods.
Moreover, those ordinarily skilled in the art will appreciate that
various aspects of the disclosure may be practiced with a variety
of computer-system configurations, including hand-held devices,
multiprocessor systems, microprocessor-based or
programmable-consumer electronics, minicomputers, mainframe
computers, and the like. Any number of computer-systems and
computer networks are acceptable for use with the present
disclosure. The disclosure may be practiced in
distributed-computing environments where tasks are performed by
remote-processing devices that are linked through a communications
network. In a distributed-computing environment, program modules
may be located in both local and remote computer-storage media
including memory storage devices. The present disclosure may
therefore, be implemented in connection with various hardware,
software or a combination thereof in a computer system or other
processing system.
To summarize the operation of relative positioning system 100 of
FIG. 1, in one illustrative method a first wellbore 10 is drilled
using BHA 14. As it is being drilled, excitation source S emits
electromagnetic waves 20 toward wellbore 10, which are received by
sensors 18 which, using processing circuitry onboard BHA 14,
generate corresponding first measurement signals. As will be
described in more detail below, the first measurement signals also
comprise survey measurements of the first wellbore obtained during
logging operations, for example. Thereafter, in this example, BHA
14 is also used to drill a second wellbore 12, whereby
electromagnetic waves 22 are emitted by excitation source S, and
received by sensors 18 to produce second measurement signals. The
second measurement signals also include survey data previously
obtained. Then, using the principles described herein, processing
circuitry calculates the differences between the first and second
measurement signals (i.e., differential measurements). The
differential measurements are then utilized to determine the
relative positions of wellbores 10 and 12.
FIGS. 2A-2B shows an illustration of a triaxial magnetic dipole
sensor configuration at each well, in relation to a linear surface
source, according to certain illustrative embodiments of the
present disclosure. In this embodiment, only absolute signals are
utilized in each well since gradient signals over such long
distances would be small, thus creating a signal to noise problem.
Here, we show two wells, an injector and producer as previously
described in relation to FIG. 1. Even though one sensor station per
well is shown, multiple sensors can be used along the BHA. Thus,
certain embodiments may include an array of triaxial sensors in
either or both of the wells. In other embodiments, bi-axial
receivers may be used in cases where excitation source geometry and
sensor orientation is well defined and well controlled.
Referring to FIGS. 2A-2B, magnetic field distribution due to a
linear source of current I in both wells can be written as:
.times..times..times..times..pi..times..times..times..times..times..times-
..times..times..pi..times..times..times. ##EQU00001## where G is
the measurement gain of the magnetometers; r.sub.1 is radial
distance of the producer from the source; r.sub.2 is radial
distance of the injector from the source; H.sub.y1 is the
y-component of the magnetic field measurement at the producer; and
H.sub.y2 is the y-component of magnetic field measurement at the
injector. The term G typically depends on the particular
environment that the magnetometer is operating at such as, for
example, the temperature and presence of magnetic materials in the
formation. By utilizing the same magnetometer in the producer and
injector wells, and also through corrections on temperature
variations on the sensor electronics, G can be controlled to be the
same between the two wells. By measuring the difference in magnetic
fields between the wells and the average magnetic fields in both
wells, the difference in ranges (i.e., differential measurement)
can be calculated as:
.times..times..times..times..times..times..times..times..times..times.
##EQU00002##
Here it can be observed that this differential measurement between
the ranges is calculated independent of terms G and I, when r.sub.1
and r.sub.2 is provided by a survey measurement. It can also be
observed that the error in the difference between the ranges will
be in the order of the percentage error in the survey depth, which
is generally lower than 5%. The azimuthal direction to the producer
and the injector can be calculated as:
.PHI..function..times..times..times..times..times..times..PHI..function..-
times..times..times..times..times. ##EQU00003## Similar to the
differential measurement calculated in Eq (2), this calculation
does not depend on G or I. Finally, through geometric calculation,
the distance between the wells can be found as:
.DELTA..times..times..times..times..times..times..function..PHI..PHI..tim-
es..times..times..times..function.
.times..PHI..PHI..times..times..times..times..times..times..times..times.-
.times..times..times..times..function..function..function..times..times..t-
imes..times..function..times..times..times..times..times.
##EQU00004##
Again, this particular distance calculation does not depend on
particular values of G or I, when r.sub.1 and r.sub.2 is provided
by a survey measurement. It can also be observed that the error in
the distance between the wells will be in the order of the
percentage error in the survey depth, which is generally lower than
5%. Accordingly, electromagnetic and survey measurements from the
first well are used to calibrate the formation model, which is then
used to improve the interpretation of measurements from the second
well. As a result, the relative position of the wells is accurately
determined in a more robust and efficient manner than conventional
approaches.
The description above targeted a special case with a linear
excitation source shape. This type of source is usually not
feasible operationally because it requires a physical line to be
placed linearly on a terrain which may not be linear or accessible.
Note, however, the same concept can be generalized to any source
shape by following the illustrative method described below. FIG. 3
is a flow chart 300 for a relative positioning method useful for
downhole ranging applications, according to certain illustrative
methods of the present disclosure. The example of method 300, the
surface system is deployed and activated at block 302, and kept
unchanged throughout the application. It should be emphasized that
stability of the surface system (e.g., excitation source and
return) is crucial for success of the proposed method, which can be
achieved by different methods including, for example, measurement
and feedback control and thermal insulation of the excitation
source S.
At block 304, tri-axial electromagnetic measurement signals are
acquired in the first well are taken, which are denoted as
Hx.sup.1(l), Hy.sup.1(l) and Hz.sup.1(l) where l is the measured
depth of the sensor during the measurement. EM measurements
typically have units of electric field, magnetic field, voltage or
current. The EM measurements are preferably taken on a LWD BHA in
an open-hole environment; however, a wireline conveyed system, or
cased-hole environment (FIG. 1, e.g.) can also be used. As
mentioned before, a bi-axial measurement can also be used in cases
where the sensitivity of the third measurement is not
essential.
At block 306, a survey of the first well is also taken, which is
denoted as S.sup.1(l). The survey measurements can be in units of
relative position and orientation relative to a reference point and
coordinate system. At block 308, EM measurements in the second well
are taken and denoted as Hx.sup.2(l), Hy.sup.2(l) and Hz.sup.2(l),
in the same way as described in block 304. At block 310, survey
measurements in the second well are taken similar to the first well
as described above, and denoted as S.sup.2(l). At blocks 312, 314
and 316, different relative measurements between the two wells are
calculated (i.e., the term "relative measurement" is broadly used
herein to denote blocks 312, 314 or 316). For example, at block
312, the difference between the measurement signals of the
wellbores is calculated using Eqs. (1)-(4) previously described,
denoted as Hp.sup.1 and Hq.sup.2 (p and q can by the x, y or z
measurements), also referred to as the differential
measurement.
During operation of certain embodiments, the gain and current of
the system is kept the same by utilizing the same sensor system in
both the producer and injector wells, and controlling the surface
excitation source S and downhole sensor conditions the same. In
order to compensate for the differences in temperature in the two
wells, a temperature correction may be applied to the measurements
based on a surface heat run, for example.
The differential measurement of block 312 may be normalized in
certain methods. At block 314, ratios of the differential
measurement to absolute measurements of the first and second
wellbores are calculated, denoted by (Hp.sup.1-Hq.sup.2)/Hr.sup.1
and (Hp.sup.1-Hq.sup.2)/Hr.sup.2). In addition or in the
alternative, at block 316, a ratio of the absolute measurement of
the first well to the second well, or vice versa is calculated, as
denoted by Hp.sup.1/Hq.sup.1, Hp.sup.2/Hq.sup.2, H.sup.1/Hq.sup.2,
and Hp.sup.2/Hq.sup.1. These ensure that the measurements that are
used in subsequent processing are normalized and independent of
receiver gain and source current levels.
Finally, at block 318, an inversion procedure is conducted to
determine the relative position of the wells, where an EM forward
model result is calculated and compared against the real data. A
numerical optimization is conducted to find the input parameters
that match the synthetic and real results. In this example, the
inversion is entirely based on the normalized measurement signals
(differential to absolute or absolute to absolute ratios), using
the survey data from both wells. Finally, the drilling path may be
adjusted based on the calculated distance and relative direction
between the wells. The forward model that is used in this inversion
can be based on a homogeneous, 1D, 2D or 3D parameterization of the
formation, with or without the borehole. Here, dimensionality may
be defined as the number of dimensions where the material
parameters are varying. The forward model can be based on, for
example, finite different, finite element, analytical,
semi-analytical, method of moments, integral equation, or any other
type of electromagnetic modeling method.
In alternative embodiments, a known or assumed formation electrical
resistivity, permeability and/or permittivity distribution can be
input to the model to obtain more accurate results. In yet other
embodiments, the electrical model of the formation can be updated
based on a comparison between the modeled and real measurements.
For example, resistivity of the model can be increased or decreased
to better match the modeled and real measurements.
Still referring to FIG. 3, one or more of the blocks 312 (i.e.,
differential measurement), 314 (i.e., normalized measurement) and
316 (i.e., absolute ratio measurement) may be used together in the
inversion of block 318. Blocks that are not used in the inversion
can be skipped. The advantage of normalized measurement in block
314 compared to the differential measurement in block 312 is that
any measurement errors or drifts that are common to both the first
and second well measurements will be cancelled out by the ratio in
block 314. Block 316 will perform similarly to block 314 in
principle as long as a corresponding set of ratios are used, since
normalized signals in block 314 can be represented as linear
combinations of terms in block 316.
Unlike prior art systems which focus on absolute measurements of
the two wellbores, embodiments of the present disclosure determine
the relative position of two wellbores. By using the relative
measurement approach described herein, even though the exact
position of each wellbore cannot be accurately identified, their
relative positions can be accurately identified. With reference
back to FIG. 1, the "differential measurements" measure the
difference between fields at two points that are closer to each
other. As a result, the relative signal levels are usually much
smaller than the absolute signal levels that are received at
individual points. As a result, the range of successful reception
of a differential measurement is smaller compared to an absolute
measurement. FIG. 4 is a graph of the ranges of absolute and
differential measurements as a function of distance from the source
to target. It shows the uncertainty of absolute measurement versus
the differential measurements. In this example, both differential
and absolute measurements can be made both in the injector and
producer, but the differential measurement is more accurate due to
the gain and current normalization that it provides.
In view of the foregoing, a simulated example of the present
disclosure will now be described. A synthetic case with a 10000
feet long linear source, parallel source and receivers is
considered to illustrate the advantages of the present disclosure.
The source current is set at 10 Amperes and an excitation frequency
of f=0.1 Hz is used. In this example, without loss of generality
and for illustrative purposes, the wells are assumed to be aligned
in the horizontal plane. The well paths and surveys are shown in
FIG. 5, which shows a 5% error is introduced to both the producer
and injector surveys, which is in line with what is expected in
practice. As can be seen from FIG. 5, with 5% error in each survey,
the distance between well estimation from the surveys become
approximately 1 foot, which is very inaccurate. FIG. 6 shows the
Hy(l) magnetic fields that are measured at the producer and
injector wells. In FIG. 6, it is seen that the magnetic field
levels are within measurable range.
FIG. 7 shows the distance between the wells that is calculated by
applying the methodology described in Equations (1)-(4). It can be
seen that very accurate ranging results can be obtained without
knowing precisely the current or receiver gain levels, through the
use of self-normalization. It can also be seen that the survey
errors did not create any significant error in the range estimation
as predicted. In this example, this is partially due to
cancellation of errors when the survey ranges are added in Eq. (2).
Even in the worst case of constructive 5% errors in both producer
and injector wells, a maximum of 10% error will be observed in
range estimation which is acceptable.
The embodiments described herein may be altered in a variety of
ways. For example, in one method, a BHA having a first sensor as
described herein may be deployed along a first wellbore. A first
measurement signal is then acquired using the first sensor. The BHA
is then retrieved from the first wellbore, and thereafter deployed
along a second wellbore, whereby a second measurement signal is
acquired using the first sensor. Alternatively, a second sensor may
be used to acquire the second measurement signal. In yet another
method, the first and second sensors are calibrated using the same
excitation source. The BHA may then be steered along a desired path
(or to avoid a structure) based upon the relative measurements.
Methods and embodiments described herein further relate to any one
or more of the following paragraphs:
1. A method for downhole ranging, comprising acquiring first
measurement signals in a first wellbore; acquiring second
measurement signals in a second wellbore; calculating a relative
measurement between the first and second measurement signals; and
determining a position of the second wellbore relative to the first
wellbore using the relative measurement.
2. A method as defined in paragraph 1, wherein calculating the
relative measurement comprises calculating a differential
measurement between the first and the second measurement
signals.
3. A method as defined in paragraphs 1 or 2, wherein calculating
the relative measurement further comprises calculating a ratio of
the differential measurement to the first or second measurement
signals.
4. A method as defined in any of paragraphs 1-3, wherein
calculating the relative measurement further comprises calculating
a ratio of the first measurement signal to the second measurement
signal; or the second measurement signal to the first measurement
signal.
5. A method as defined in any of paragraphs 1-4, wherein
determining the position of the second wellbore comprises
performing an inversion using survey data from the first or second
wellbores.
6. A method as defined in any of paragraphs 1-5, wherein
determining the position of the second wellbore comprises
performing an inversion using survey data from the first or second
wellbores; and a ratio of the differential measurement to the first
or second measurement signals.
7. A method as defined in any of paragraphs 1-6, wherein performing
the inversion comprises performing the inversion using a ratio of
the first measurement signal to the second measurement signal; or
the second measurement signal to the first measurement signal.
8. A method as defined in any of paragraphs 1-7, wherein acquiring
the first measurement signal comprises deploying a first sensor
along the first wellbore; emitting a first source signal toward the
first wellbore; and measuring the first source signal using the
first sensor, thereby acquiring the first measurement signal; and
acquiring the second measurement signal comprises: deploying a
second sensor along the second wellbore; emitting a second source
signal toward the second wellbore; and measuring the second source
signal using the second sensor, thereby acquiring the second
measurement signal.
9. A method as defined in any of paragraphs 1-8, wherein acquiring
the first and second measurement signals comprises emitting a
source signal toward the first and second wellbores using a surface
excitation source.
10. A method as defined in any of paragraphs 1-9, wherein acquiring
the first and second measurement signals comprises acquiring
bi-axial or triaxial measurement signals.
11. A method as defined in any of paragraphs 1-10, wherein the
first measurement signal is acquired using a first sensor; and the
second measurement signal is acquired using the first sensor at a
different time.
12. A method as defined in any of paragraphs 1-11, wherein the
first measurement signal is acquired using a first sensor; and the
second measurement is acquired using a second sensor.
13. A method as defined in any of paragraphs 1-12, wherein the
first and second sensors are calibrated using a same excitation
source.
14. A method as defined in any of paragraphs 1-13, wherein
acquiring the first and second measurement signals comprise at
least one of acquiring absolute, phase, or real or imaginary
measurements.
15. A method as defined in any of paragraphs 1-14, wherein the
first and second measurement signals are acquired using a sensor
deployed on a bottom hole assembly.
16. A method as defined in any of paragraphs 1-15, further
comprising steering the bottom hole assembly deployed along the
second wellbore using the determined position of the second
wellbore.
17. A method as defined in any of paragraphs 1-16, further
comprises avoiding the first wellbore using the determined position
of the second wellbore.
18. A system for downhole ranging, comprising an excitation source
positioned adjacent a surface location; a bottom hole assembly to
be positioned along a wellbore; one or more sensors positioned
along the bottom hole assembly; and processing circuitry coupled to
the sensors and configured to implement a method comprising:
acquiring first measurement signals in a first wellbore; acquiring
second measurement signals in a second wellbore; calculating a
relative measurement between the first and second measurement
signals; and determining a position of the second wellbore relative
to the first wellbore using the relative measurement.
19. A system as defined in paragraph 18, wherein calculating the
relative measurement comprises calculating a differential
measurement between the first and the second measurement
signals.
20. A system as defined in paragraphs 18 or 19, wherein calculating
the relative measurement further comprises calculating a ratio of
the differential measurement to the first or second measurement
signals.
21. A system as defined in any of paragraphs 18-20, wherein
calculating the relative measurement further comprises calculating
a ratio of the first measurement signal to the second measurement
signal; or the second measurement signal to the first measurement
signal.
22. A system as defined in any of paragraphs 18-21, wherein the
excitation source is at least one of an electrode source, loop
source, or dipole source.
23. A system as defined in any of paragraphs 18-22, wherein the
first wellbore is a producer well; and the second wellbore is an
injector well.
24. A system as defined in any of paragraphs 18-23, wherein the
first wellbore is a blow out well; and the second wellbore is a
relief well.
Moreover, the methods described herein may be embodied within a
system comprising processing circuitry to implement any of the
methods, or a in a computer-program product comprising instructions
which, when executed by at least one processor, causes the
processor to perform any of the methods described herein.
Although various embodiments and methodologies have been shown and
described, the disclosure is not limited to such embodiments and
methodologies and will be understood to include all modifications
and variations as would be apparent to one skilled in the art.
Therefore, it should be understood that the disclosure is not
intended to be limited to the particular forms disclosed. Rather,
the intention is to cover all modifications, equivalents and
alternatives falling within the spirit and scope of the disclosure
as defined by the appended claims.
* * * * *